Scada Siemens

Siemens AG 2008

Distribution NetworkAutomation & Control

SeminarJan 29/30, 2008Tehran/Iran

Dr. Roland Eichler

Jan 2008

Siemens AG 2008Power Transmission and DistributionDr. Roland Eichler

Seminar

Substation Substation Substation

Outstation

Outstation

OutstationOutstation



Outstation

Control Center

Strategies for distribution automationControl in substations and outstationsCommunicationProcess optimization in the Control

Center and customer related activities

Jan 2008


Seminar Contents (I)

Section 6: Distribution automation standards

Section 5: Selection criteria for hardware, software and communications

Section 4: Which parameters should be measured or controlled ?

Section 3: Selection of substations to work under automation automation layout

Section 2: Impacts on planning of distribution automation

Section 1: Goal, task and aspects of distribution automation

Tuesday, Jan 29, 2008

Jan 2008


Seminar Contents (II)

Section 7: SCADA functionalities

Section 8: DMS functionalities

Section 9: Case study presentation

Section 11: Maintenance and support procedures

Section 10: Distribution system automation personnel skills

Wednesday, Jan 30, 2008

Jan 2008










Jan 2008


Mission of the Electricity Supply System

The primary aim of an electricity supply system is to meet the customers demands for energy (in sufficient quantity and quality, at the required time and at an acceptable price)

Similarity to other goods consumption processes, the Electricity Business comprises 4 basics components

Demand Production (Generation) (Sub-)Transmission Distribution

Jan 2008


Requirements to the Distribution System

Suppliers View

high efficiency with low losses few assets easy service less maintenance fast fault detection

Customers View

high availability no faults high power quality low price quick recovery

Jan 2008


Customer Requirements and Supply Standards

Availability no interrupts i.e. continuity of supply

Power QualityVoltage FrequencyHarmonics Transients

Definitions of supply reliability are quite different therefore statistic values can not be compared exactlymost countries count outages longer than 3 minutes, some define a 1

minute limit (Great Britain, Portugal)Continuity indicators are calculated in a different way

Weighted by the number of customer Weighted by the power affected (Spain, Portugal) Some consider Acts of God, some dont

Jan 2008


Power Quality Standards

Voltage in EuropeAccording IEC 61000

Voltage in the USA : the American National Standard Institute (ANSI) defines "Voltage Range " as: 120/240V 5% at the user's service entrance, and 120/240V 8,33% at the point of utilisation.

Frequency The vast majority of equipment appliances are not much sensitive to variation of

frequency. Furthermore, in interconnected networks (e.g. UCPTE,..) the frequency (50 Hz or 60 Hz) is generally very stable and secondly source of problems.

QualityAccording IEC 61000

Jan 2008


Power Interrupt Statistic in Europe

Length of power interrupts in minutes per year (1999) in some countries

Source: Council of European Energy Regulators CEER 2001

1525

57 63

152

180191

157

364

0

50

100

150

200

250

300

350

400

GER NLD FRA GBR SWE NOR ITA SPA POR

Country

T

i

m

e

[

m

i

n

]

Customer-weighted indicators Power-weighted indicators

Jan 2008


Domestic $ 0.15 / kW + $ 0.30 / kWh

Agriculture

$ 0.75 / kW +

$ 2.50 / kWh

Large Indust

ry $ 2.70 / kW

+ $ 3.00 / kW

h

Small In

dustry

$ 1.35

/ kW + $

5.25 / k

Wh

Trade

& Se

rvices

$ 1.9

5 / kW

+ $ 9

.60 / k

Wh

Customers Costfor an Unexpected

Outage[ $ per Interrupted kW ]

Outages Duration

[ Minutes ]

Swedish nationwide surveyfor unexpected outages, 1993

Social Cost for Unplanned Outage

4020

1

2

3

4

5

6

7

Jan 2008


Transmission 33 - 420 kV

27%

Distribution 1-22 kV 73%

Distribution 1-22 kVTransmission 33 - 420 kV

Energy not Supplied due to Fault Outages

Source: Cigr Conference, Paris, 2002

Jan 2008


Why to Improve the Distribution System

The transmission and the sub-transmission system have already high reliability

Therefore:Distribution Automation has the best ratio Improvement to Invest

Strategies to optimize the distribution system n-1 strategies are very expensive structure of the system can not be changed easily

But even with rather cheap measures one can reduce the outage times dramatically

Jan 2008


Maintenance

Erection

Commissioning

Assembly

Design

Equipment

5%

10%

25%

10%

40%

10%

10kV Overhead Line

Diminishing ReturnsC1 = C2Rel1 >> Rel2

C1

Rel1

C2Rel2

0

0.2

1.0

0.4

0.6

0.8

Investment [C]

R

e

l

i

a

b

i

l

i

t

y

[

R

e

l

]

Reliability vs Investment Cost

Breakdown of Capital Expenditure

Jan 2008


Supply Quality

C

o

s

t

s

Supply Quality vs. Cost: A Macro Economic Consideration

Cost for Interrupts(Less Sold, Penalties)

Cost for Invest and Maintenance

Macro Economic CostsLimits

(Law, Standards)

Jan 2008


What is Distribution Automation

There is no fixed definition of the term.

Definition from EPRI 2004: The objective of (Advanced) Distribution Automation Function is to enhance the reliability of power system service, power quality, and power system efficiency,

by automating the following three processes of distribution operation control: data preparation in near-real-time; optimal decision-making; and the control of distribution operations in coordination with transmission and

generation systems (Note: Distributed Energy Resources !) operations

Others (e.g. CIRED AD HOC Working Group 2 ) add topics such as establish closer and more responsive relationship with customers.

Jan 2008


Improved automated workflow of the Operation and Planning Department ( North York Hydro )

Improved supply quality and minimising of not sold kWh (CIRED 1987)

Improved efficiency and quality of service, more rational use of energy (ENEL)

Utilities view on Distribution Automation

Jan 2008


Customer Interface,

Management& Control

Loads and Meters ReadingsControl

Customer Trouble Information

Billing &Settlement

Distribution AutomationMain Function Sets

Network Operation

Operational Planning,

Optimization

Data Management

Operation Statistics and

Reporting

Fault Management

Power Import Scheduling and

Optimization

Network OperationMonitoring

Network OperationSimulation

Technical Data Management

Network ControlSwitching Actions

Scheduling

Dynamic Data Management

Source: CIRED Ad Hoc Working Group 2

GeographicalDisplays

ManagementInformation

System

Maintenance Management

Operation Feedback Analysis

Maintenance Works Scheduling

and Control

Jan 2008


Benefits in Network Operation (I)

Improving the quality of serviceData acquisition, monitoring and remote control also at remote sites

allows responding to alert and emergency conditions quickly and confidently and with the correct action, e.g.

low voltage unbalanced flows low power factor overload

Less and shorter outages lead to increased revenue

Better network supervision means less equipment failureEquipment lifetime is lengthenedCost for maintenance material and manpower is reduced

Jan 2008


Increased safety and securityOperation of any electrically controllable device can be securely inhibited

at the SCADA master stationRemote outstations can be monitored for intrusion

Reduction of staff in remote outstations

Power Quality Calculations (Power Auditing) the open market imposes penalties for quality of service not compliant

with minimum characteristics.

Energy and Power Balancessome utilities have high amount of energy losses. The first step for

correcting this problem is to determine where losses larger than normal are located, this includes both technical and non-technical losses

Benefits in Network Operation (II)

Jan 2008


Improve Quality of ServiceSPM: Operator always has a clear picture about the current status and

further planned steps of each switching sequence faster switching at lower riskFloc / FISR: Shorten interruption time by automatically identifying

candidate switching actions forisolation of faultsrestoration of supplyswitching back to normal

DSPF: Detection of Limit Violations that would occur after planned switching actions avoiding overloads and accidental customer supply interruptions

Improve Efficiency of Network OperationVVC/OFR: Keep the system at the minimum of technical losses thus

reducing costFichtner Consulting estimates reduction of losses gained from optimized network operation using applications such as OFR and VVC to 0.4% 0.5% of the electrical energy delivered.

Fichtner Consulting estimates reduction of losses gained from optimized network operation using applications such as OFR and VVC to 0.4% 0.5% of the electrical energy delivered.

Benefits in Network Operation (III)

Jan 2008


Customer Interface,

Management& Control



Billing &Settlement


Network Operation


Optimization

Data Management


Reporting

Fault Management


Optimization





Scheduling





System




and Control

Jan 2008


Benefits from Automatic Meter Reading (AMR) Systems

Loss identification Loss reduction Revenue enhancement Operational Efficiency and Asset UtilizationMonitor energy balance & peak demand reductionFaster response time to customersEarn from innovative services to consumers e.g.

Load profile via web accessSecurity services e.g. door control

By using the AMR infrastructure

Power Quality system on top

Jan 2008


Customer Interface,

Management& Control



Billing &Settlement


Network Operation


Optimization

Data Management


Reporting

Fault Management


Optimization





Scheduling





System




and Control

Jan 2008


Benefits from Real Time Energy Management System (RTEMS)

Integration of meter-to-bill processes and systems Improve cash flow, and system reliability

Consolidation of customer data and meter data repositories Improve trust and reduce cost

Allowing web-based display and usage of energy demandand consumption information at the consumers site

Reduce cost, improve customer retention / satisfaction and quality

Enabling real time monitoring of power quality informationand automated response to energy distribution events

Sell power quality services and increase margin

Jan 2008


Customer Interface,

Management& Control



Billing &Settlement


Network Operation


Optimization

Data Management


Reporting

Fault Management


Optimization





Scheduling





System




and Control

Jan 2008


Obtain more information from the network for a safer, more reliable and more efficient operationextremely useful for cost efficient network planning because information

on real equipment loading avoids over-sizing e.g. for installed transformer capacityplanning of just-in-time maintenance based on actual equipment stressgeneration of logs and reports for after-the-fact system analysis and

management information; everybody can create the reports he/she needs (no software or database knowledge required, only brief handling training)Precise, on-time, and comprehensive information increases management

awareness of actual situation and increases efficiency of department co-operation

Calculation of Quality of Service Indices for individual distribution points clear proof of power supply quality

A distribution utility has reported a 100,000 US$/per year saving because new distribution substations could be better planned - at the right time at the right place.

Benefits from Management Information System

Jan 2008


Minimization of non-in-time delivered energy reduce by 20% the current values (conservative figure)

Network losses minimization reduce by 5% the current values (conservative figure)

Improved Operation efficiency10% of the Operations budget

Improved Imageequivalent or better market penetration with reduced marketing costs

Improved working conditions and environmentstable personnel, less recruitment costs (and related training)

Distribution AutomationSome more potential achievements

Jan 2008










Jan 2008


Impacts on planning of distribution automation (I)

The general benefits from distribution automation have been clarified in Section 1. This has answered the WHY of distribution automation.

The utilitys priority of goals defines WHAT shall be done i.e. what is more important to achieve:

increasing supply reliabilityincreasing power qualitydecreasing costdecreasing loss of revenueetc

This priority list will guide the selection of the most suitable program for distribution automation i.e. what will be done first.

Jan 2008


Impacts on planning of distribution automation (II)

After the utility has answered the strategic WHAT question the next question is HOW the distribution automation solution shall be implemented i.e. what are technical / environmental / legal / constraints. This concerns issues such as:

overhead vs. underground networksavailability of communication technologyavailable (inter-)national standardsalready existing automation / communication infrastructureaccessibility of substationscurrent and future importance of substationsetc

Jan 2008


Impacts on planning of distribution automation (III)

Normally there will be several proposals for achieving the WHAT goals considering the HOW constraints.

Besides the achievement of the strategic WHAT criteria there aregeneral criteria for selecting the most suitable distribution automation proposal:

flexibility of the distribution automation solution in case of changing strategic goals of the utilityflexibility for adding more services/business in the futureexpandability of the distribution automation solution in case of

growing system size e.g. due to mergers with other utilitiesreliability of the distribution automation solution itselfinvestment cost & cost for operation and maintenance of the

distribution automation solution vs. monetary achievements

Jan 2008


Components of a distribution automation solution (I)

A properly selected distribution automation solution will comprise answers to the following questions:

Which substations should be automated to what extent ?Remote metering/monitoringRemote switch control

Which data shall be collected from which substation ?Which control centers shall be built/used (centralized/distributed) ?Which redundancy concepts shall be implemented ?Which communication media shall be built/used for which type of

link?Which communication configuration shall be built (point-to-point,

network, radial, ...) ?

Jan 2008


Components of a distribution automation solution (II)

Which software packages are required ?

Which interfaces are required ?

to external control centersto external applications, such as GIS, CRM, etc

Which metering, accounting, settlement and billing process shall be applied ?

Which standards shall be used ?

Jan 2008


Components of a distribution automation solution (III)

What is the capital expenditure for such a system ?Which achievements are expected with regard to the strategic WHAT

goals ?reduction of outage frequencyreduction of outage durationcost reductionetc

How can such a system be implemented and maintained ?How can databases be populated and maintained ?How can the implementation be split in several phases for early

benefit achieving ?Which training is needed at what time for operational staff and

administration ?

Jan 2008


Anticipated Problems with Distribution Automation#1: Centralized Control System

Apprehension: Due to the automation of distribution networks the number of data points and RTU lines to be processed increases dramatically and thus exceeds the processing capabilities of centralized systems

large amount of data is not any more limiting the processing capabilities of modern SCADA/DMSmodern process interfaces can handle hundreds of RTU lines,

furthermore there are possibilities forrunning several RTU servers in parallellean RTU interfacing by means of TCP/IP based

protocolsuse of modem poolscascading of RTUs, i.e. small field RTUs talk through

large substation RTUs

Jan 2008


Anticipated Problems with Distribution Automation#2: Communication

Apprehension: The automation of distribution networks fails due to insufficient communication lines.

cascading of RTUs reduces the number of communication lines needed

alternative communication media are available

power line carrier over distribution linesmobile phone networks such as GSM, GPRSdial-up lines over public phone companies

Jan 2008


Anticipated Problems with Distribution Automation#3: Cost

Apprehension: The automation of the entire distribution network is too expensive.

in the course of energy market liberalization the pressure for cost reduction from regulation authorities on distribution companies will constantly grow and justify ever more investment in distributionautomation

cost for energy automation equipment and communication equipment is decreasing particularly for compact RTUs and dial-up connections via mobile telephone systems

distribution automation does not come as big bang; it rather grows over time closely coordinated with investment / maintenance programs for substations

Jan 2008










Jan 2008


The Last Meters: Low Voltage

115 V /125 V SystemsMainly used in USA, Canada, Brasilia, Mexico, Saudi Arabia, Korea,

Philippinestypical 60 Hz and requires transformer nearby the consumermain distribution to the end consumer is done by the MV grid

230 V / 400 V SystemsMainly used in Europetypical 50 HzOhmic power losses enable distance up to 2 km to the next MV / LV

transformermain distribution to the end consumer is done by the LV grid

Jan 2008


Structure of the Power System in USA115 V

TransmissionNational /International

SubtransmissionRegional

Low Voltage

Distribution System

Jan 2008


Structure of the Power System in Europe230 / 400 V

TransmissionNational /International

SubtransmissionRegional

Low Voltage

Distribution System

Jan 2008


Typical sub-transmission/distribution configuration

220KV220KV/33KV Rec. Stn

33KV

33KV/11KV Rec. Stn.

Compact Distribution Station Ring Main Units

11KV

X X XXX

X X X X

Scope of this seminar

Jan 2008


Urban underground MV networks

110/20kV

20/0,4kV

20/0,4kV

A

B

C D

Sc d

Circuit breaker

Load-breakingswitch

Fuse

S Isolation point

At a suitable point on the network the loop is opened by a sectionalising device S. This may be a circuit breaker, switch, fuse or link. The system then effectively operates as two radial feeders.

Jan 2008


Overhead rural MV networks

The figure shows schematically typical arrangements for a rural overhead radial feeder, with some of the manually operated disconnectors omitted for simplicity. It will be noted that each main trunk feeder has a number of lateral spurs.

Jan 2008


Substations of type 1 establish permanent communication between the control centre and the distribution substation e.g. by means of optical fibres. Often the fibres of a secondary communication network are interconnected with a node (receiving station) of the primary fibreoptic ring. Applications such as RTU and AMR use TCP/IP. IEC 60870-5-104 is recommended for RTU communication.Of course, other communication media / protocols are possible.

Battery 24/48V DC

Battery charger

RTU (IEC104)

Meter

Control & Monitor switch states,Short circuit indicators

CT, VT

motorized 11kV

Switchgear

Fibre panel 1 (2) *24

8 port Ethernet HUB

FO from R/S, S/S FO to next S/S

Fibre optic to UTPMedia Converters

Substation type #1 with permanent data access

Sample configuration

Jan 2008


Battery 24/48V DC

Battery charger

RTU (IEC101)

Dial up Modem (WLL/Fixed wired)

Energy Meter

Control & Monitor switch states,Short circuit indicators

CT, VT

motorized 11kV

Switchgear

24/48 V DC

Substations of type 2 use switched telephone communication facilities (fixed wired or mobile communication) to transfer data on demand. The demand for data exchange can be initiated by the control centre or the distribution substation itself. The control centre needs to control switchgears remotely, to ask for data update or just to test the connection. The substation need to call in the control centre if there is some urgent data to transfer, for example a fault indication on a 11kV incoming or outgoing line.

Substation type #2 with temporary data access

Sample configuration

Jan 2008


Steps of Distribution AutomationStep 0: Centralization of distribution system operation

centralized distribution system operation is less costly

centralized distribution system operation reduces time to restore supply after disturbances

existing mixed structures of local and centralized operation often have grown over time but do not have justification as of today

mixed structures in case of disturbances, i.e. local operation only temporarily, are questionable in terms of organization reliability

Jan 2008


Steps of Distribution AutomationStep 1a: Automation of feeder heads in HV/MV substations

in case of a new HV/MV substation the whole scope of automation shall be built in:

remote signaling of all switching element statuses remote control of circuit breakersdigital protection devices provide analog measurements in

normal operation and fault operation

in case of retrofitting HV/MV substations the following priority applies

must: fault information from protection equipment per field

optional: remote control of circuit breakersanalog measurements of feeder currents

nice-to-have: more switching status information (isolator, earthing switch, ...)

Jan 2008


Steps of Distribution AutomationStep 1b: Automation of major switching substations

Major switching substation:three (3) outgoing feeders or morecircuit breaker and protection

In case of a new switching substation the whole scope of automation shall be built in (see Step 1a)

In case of retrofitting switching substations the same priorities apply as in Step 1a.

Jan 2008


Steps of Distribution AutomationStep 1c: Remote signaling of selected fault current sensors

With this step the utility has reached the level of automated centralized fault location:

evaluation of topology informationevaluation of fault impedancesevaluation of fault current sensor informationconsideration of additional information received via phone

Jan 2008


Steps of Distribution AutomationStep 2a: Automation of selected MV/LV substations

Selected MV/LV substations:

normally open section pointmidway of long feeders

Remote control of load switchesThis normally implies the necessity to motorize the switches.

Jan 2008


Steps of Distribution AutomationStep 2b: Automation of selected customer substations

Selected customer substations:

high-volume consumerhigh-sensitive consumer

remote signaling of fault informationremote switchingremote signaling of analog measurements

This enables new business opportunities for providing high-quality power supply services to those customers.

Jan 2008


Selection of distribution substations for automation

For the selection of distribution substations for automation two main questions have to be answered:

(A) What is the most reasonable and beneficial rate of automation for distribution substations?

(B) Which dedicated distribution substations shall be automated ?

The goal of distribution substation automation is basically to reduce the average interruption time of energy supply in the distribution network. In case of a feeder trip the SCADA/DMS operators get fault indication from automated distribution substations. Within a short time a part of the affected consumers can be re-supplied by reconfiguring the distribution network by remote control actions from the SCADA/DMS. DMS applications will support the operator in defining the most appropriate switching sequence (Section 8).

Jan 2008


Selection of distribution substations for automationQuestion (A): Automation Rate (I)

A fault on a cable section causes the feeder to trip. Two distribution substations will send fault indications and fault-direction to the control centre. Based on this information the operator can re-supply ~ 50% of the affected consumers by performing switching actions 2 - 5. This can be done within a time period of 3 minutes.

Normally open point

1. trip

2. open

4. open5. close

650 feeders4099 distribution substationsD6,5 substations / feeder

2,2 million consumersD537 consumers / substation

R/S feederR/S feeder

Fault indicator

Automated substation

3. close

About 50% of the affected customers re-supplied after 3 minutes.

Automation rate assumed to be 25%.

Jan 2008


Selection of distribution substations for automationQuestion (A): Automation Rate (II)

Compared to non-automation, the restoration crew can work faster since the area of intervention is only a part of the feeder. Fault isolation and service restoration are done by conventional methods. The crew on site can be supported by the operators in the control centre. Average conventional restoration time is estimated to be reduced by 50 % (40 minutes 20 minutes).

Remaining 50% of the affected customers re-supplied after 20 minutes.

R/S feederR/S feeder

Fault indicator

Automated substation

Automation rate assumed to be 25%.

Jan 2008


Selection of distribution substations for automation Question (A): Automation Rate (III)

As result of this scenario the service restoration time will be reduced from approximately 40 minutes to approximately 11 Minutes.

50 % of consumers are re-supplied after 3 minutes50 % of consumers are re-supplied after 20 minutes=> average interruption time ~11 minutes

This kind of estimation of outage time reduction can be repeated for other values of the automation rate.The diagram on the next page indicates the average interruption time as function of the number of automated substations (magenta) taken from a study case. Relevant study case data are given on the following page. The blue curve is representing the Net Present Value (cost/benefit ratio). The costs are based on the substation adaptation investments, the benefits are calculated from more energy sold due to reduced average interruption time.

Jan 2008


Detailed Case Study on Cost-Benefit-Analysis of Distribution Automation with different Automation Rates in Section 9.

Selection of distribution substations for automation Question (A): Automation Rate (IV)

Jan 2008


Selection of distribution substations for automation (VI)Question (B): Selection of Substations

The selection of dedicated substations for automation does not follow a strict and simple algorithm. It is rather guided by fuzzy criteria on two levels: Feeder level

Such feeders will be preferred that have higher load density higher fault density than others

Substation levelObviously the substation with normal open points will be automated first on a selected feeder.As regards other substations, the leading criterion is the load that can be affected i.e. those substations will be preferred that have

large industrial consumers connectedspur lines with high load connected

Finally, the time needed for manual switching plays a role i.e. those substations will be preferred that have

long travel time to reach

Jan 2008










Jan 2008


Data to be collected from HV/MV Substations

Active Power, Reactive Power, Voltages, Currents from allincoming feedersoutgoing feederscapacitor banks etc

Switch Positions of the Isolators (Single Pole)Circuit Breakers (Double Pole)

Indications of other auxiliary devices such as UPS, Battery system, Chargers, Communication Devices etc.Status from the protection devicesTransformer tap position

Jan 2008


Data to be collected from Distribution S/S

AlarmCharge low

AlarmCharger failure

AlarmPower supply failure

Battery SystemAlarmFault current sensors

AlarmPhase-to-ground short circuit

AlarmPhase-to-phase short circuit

Protection (each feeder)Measured ValueI / P / Q / V

Analogs(Command)StatusLoad switches

CommandStatusCircuit breakers

SwitchesOutput from SCADAInput to SCADA

Jan 2008


Step 2:

Line/cable segmentengineering data

Typical load curves forload transformers

220 kV bus

33 kV bus

33 kV bus

11 kV busM

M

M M

Data to be collected for distribution automation

Step 0:

SCADA data model

Step 0:

SCADA data model

ReceivingSubstation

Bulk supplySubstation

1. Extend by SCADA data model of distribution feeders (topology, switches) enabling Operation Applications (Section 8)

2. Extend by engineering data of line/cable segments and load models enabling Distribution Network Applications (Section 8)

3. Add measurements from automated distribution substations; substitute load models

Step 1:Extended SCADA

Data Model

M MM M

Step 3:Measurements

from distributionautomation

Jan 2008


I> (t)

tdtpick-up time dt selectable: 40 oder 80 ms

enveloping of failure currentIS1

selected pick-up current

criterion Is1 and dt fullfilled-> indication is activated

Integrative measurement avoids erroneous indication!Red signal curves must not

activate the indicator

Short-circuits and earth-faults indicators

For effective failure detection and location short-circuits and earth-faults must be observed. Combined short-circuit and earth-fault indicators are most economical. Indicators can be installed on outgoing feeders of RMUs. The fault detection facility generates alarms in case of high current peaks. However, the facility shall prevent faulty indications due to magnetizing-inrush currents, other transient and no-fault conditions.

Jan 2008


Knotenpunktstationnodal point substation

I>>IeRMU

RMU I>>Ie

RMU RMU

RMURMURMU

UmspannwerkPower substation

I>>Ie

I>>Ie

I>>Ie

I>>Ie

I>>Ie

I>>Ie

I>>Ie

Fault detection in low resistance terminated networks by means of short-circuit indicators

Jan 2008


Typical Repairing of Permanent Faults

Protection has tripped circuit breaker CBTransient fault? Automatic recovery? Localize fault

phone calls, relay data, Remote Terminal Units (RTU), visually

Open isolator and ground equipmentRestore supply as much as possibleDo nessesary repair workFault removed, line repairedRemove grounding and close isolator or replace fuseSwitch back to normal state

Jan 2008


Urban vs. Rural Regions

Urban underground cables with less external faults

Rural a lot of overhead lines intermediate short circuits birds trees wind Auto recloser strategies

Jan 2008


Distribution Automationin Urban AreasExample for Ring Main Automation

Jan 2008


OC

OC

FI

Typical open ring configuration

OC: over current protectionFI: fault indicator

Jan 2008


Outstation (Ring Main Station, Satellite Station)

Jan 2008


-Q01

-A5

1

3

-T1

-T5

-Q01

-A5

1

3

-T1

-T5

-Q01

-A5

1

-F1

Ring Unit 1

Ring Unit 2

Feeder to LV trans-

former

M M M

Double indications:Ring unit 1 isolator On/OFFEarth switch 1 On/OFFRing unit 2 isolator On/OFFEarth switch 2 On/OFFFeeder On/OFFEarth switch Feeder On/OFF

Single indications:Short circuit indicator RK1 Short circuit indicator RK2Fuse blownGrouped Indication Auxiliary power failure Transformer temperature alarmRemote control offUPS failureStation open

Meters (optional):Meter feeder

Double commands:Ring unit 1 isolator On/OFFRing unit 2 isolator On/OFFFeeder On/OFF

Analogs (optional):Ring unit 1 Current Phase L2Ring unit 1 Voltage L2-NRing unit 2 Current Phase L2Ring unit 2 Voltage L2-N

Typical mini RTU solutions

Ring main unitwith one feeder

Jan 2008


Automation in a MV Ring (1)

Example of network configuration. The network is divided into four sections. In the example is there a fault between SB21 and SB22.A central control unit is placed with the circuit breakers (E1,E2). The circuit breakers could be taken in and out from the central control unit.Decentral control units are placed with the line switches in each section(SB11,SB-R,SB21 and SB22) .These units get information from a voltage sensing system and control each line switch. In a ring configuration it is a must to have a voltage sensing system on both sides of the line switch.

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



With a fault in the network configuration, the protection relay will take the circuit breaker (E2) out. The central control unit will try to put the circuit breaker in, but in a faulty network configuration the protection relay will take out the circuit breaker again.

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



This procedure indicates to all units (SB21,SB22 and SB-R) that the network configuration is faulty, and the automatic sectioning starts.All decentral control units (SB21 and SB22) take out the line switches .

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



The central control unit closes the circuit breaker after 20 seconds, to test the first part of the network configuration .

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



After 40 seconds the decentral control unit (SB21) closes the line switch.

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



Because this part of the configuration (SB21 SB22) is faulty, the central unit will take out the circuit breaker. The decentral control unit (SB21) discovers that the voltage only was in for a short time, and then takes out the line switch and locks it.

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



The decentral control unit (SB22) discovers that the voltage was in only for a short time, and because of the voltage sensing system of both sides of the switch, the unit knows that the fault is between SB21 and SB22. The decentralcontrol unit (SB22) will then lock the line switch.

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008



The decentral control unit (SB-R) have detect the start of the automatic sectioning.The decentral control unit (SB-R) has not detected any voltage on the side SB-R SB22. After a time (60 seconds) the unit knows that the fault is between SB21 and SB 22, and the line switch (SB-R) is closed.Now at this time the part between SB21 and SB22 (the faulty) is disconnected from the healthy part of the network configuration.

200 40 60 [sec]

E1

E2

SB11

SB21 SB22

SB-R

Jan 2008


Distribution Automationin Rural AreasSectionalizer

Jan 2008


Sectionalizing in Overhead Lines

Sectionalizer enable a system for automatic sectioning in a network configuration. Automatic sectioning is based on switching on and out line switches and circuit breaker in a controlled sequence to find errors in the network. When the errors are found, the system will take out the faulty part of the configuration.

Jan 2008


Sectionalizing in Overhead Lines

Example of network configuration. The network is divided into six sections (S1 S6)

Circuit breaker Load-breakingswitchPower

TransformerVoltage sensing

system

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (1)

With at fault in the network configuration, the protection relay will take out the circuit breaker.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (2)

The central control unit (E1) will try to put the circuit breaker in but in a faulty network configuration.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (3)

The protection relay will take out the circuit breaker again.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (4)

This procedure indicates to all units (E1 and L1 .. L5) that the network configuration is faulty, and the automatic sectioning starts.The automatic sectioning starts at relative time 0 seconds.All decentral control units (L1 .. L5) take out the line switches .

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (5)

The central control unit closes the circuit breaker after 20 seconds, to test the first part of the network configuration (S1).

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (6)

After 40 seconds the decentral control unit (L1) closes the line switch.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (7)

Because this part of the configuration (S2) is faulty, the central unit (E1) will take out the circuit breaker.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (8)

The decentral control unit (L1) discovers that the voltage only was in for a short time, and then takes out the line switch and locks it. At this time the section S2 (the faulty) is disconnected from the healthy part of the network configuration.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (9)

After 60 seconds the central unit (E1) closes the circuit breaker.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (10)

The decentral control unit (L2) closes the line switch in due to the voltage sensing system.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (11)

After 80 seconds the decentral unit (L3) close the line switch in due to the voltage sensing system.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (12)

After 100 seconds the decentral unit (L4) close the line switch in due to the voltage sensing system.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (13)

Because this part of the configuration (S4) is faulty, the central unit (E1) will take out the circuit breaker.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (14)

The decentral control unit (L4) discovers that the voltage only was in for a short time, and then takes out the line switch and locks it. At this time the section S4 (the faulty) is disconnected from the healthy part of the network configuration.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (15)

After 120 seconds the central unit closes the circuit breaker and the automatic sectioning is finished. The decentral control unit (L5) could be designed to close the line switch after 120 seconds.

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer (16)

The central control unit sets outputs (lamps) for each section (S1 S6) which is faulty.It is also possible to send this information to a network control system via IEC 6870-5-101 protocol, or/and send SMS messages.

Seenextpage

20 400 60 80 100 120 140 [sec]

E1

L1

L2 L4 L5

S2: 250 kW

S3: 375 kW

S5: 250 kW

S6: 150 kW

S1: 500 kW

L3

S4: 250 kW

e. g.110/20kV

Jan 2008


Sectionalizer: Switch and Control

Line Switch with voltage transformer

Electronic with storage battery,local control andcommunication

Jan 2008










Jan 2008


BusinessServices

IT Integration

ASP

Administration

Operation

E-Commerce

Maintenance

Field data acquisition,local control & automation

Communication

Network control &supervision (single-or multi-utility)

Added value network management & optimization(applications and systems)

Integrated utility business operation

xxxx x xxx xxx xx

MetersSubstation automation

ProtectionLocal automation

RTUs

PowerExchange

$$TraderPartner, market, etc.

Multi-site

SCADAetc.DB

Networkplanning

Networkinformation

Meter datamanagement

...Advanced applications

(EMS, DMS, EBM, Trading)

Informationgateway

...Asset

ManagementEnergy Sales

& Care

Enterprise Integration Bus

Data Warehouse

MISF&A

Gateway

Power Systems Control and Energy Management Multi-Level Environment

Private & public networks

Jan 2008


Optical Fiber

Radio

Copper Cable

Power Line

Public Network

GSM/CDMA Network

Communication Media

Jan 2008


BackboneNetwork

RTU

RTU

RTU

RTU

RTU

MV - Line

RTU

MV - Line

Backbone Network / Access network

Jan 2008


Control Center

TCI

No. 1 No. Z

RTU

MV - Line

RTU

RTUMUX

Optical Fibre

Backbone Network / Distribution Data Acquisition

Jan 2008


Aspects of Network Design

Costs Reliability

PerformanceRegulations

Network Design

Jan 2008


Communication Selection CriteriaLeased Public Line

The telephone company provides direct point-to-point connectivity between the RTU location and the control centre. On both end of the communication, a suitable modem appropriate to bandwidth (9600 bauds, 86 Kbps) is required.

The cost of the communication of this nature comprises the fixed cost to be paid as one-time charges (for Registration fees, Installation fees of the equipment) and the operational charges (for periodical subscription as well as usage).

Though this type of communication facility seems to be economical, on a long term it may not turn up to be cost-effective, since one has to pay the periodical operation charges.

The other disadvantage is due to frequent failures of the lines, dependence of third party state-owned service provider.

This type of communication has limitations for future expansion as the number of RTUs / mRTUs increases.

Jan 2008


Communication Selection CriteriaDial-up Public Line

Few telephones / modems are provided having dial-up facility at the control centre end, whereas at the RTU / mRTU ends the modems are to be provided with answering facility.

For a real-time operation, this kind of communication is not preferred due to the time consuming dial-up and answering process. However, for Automated Meter Reading or for checking the status of reclosers after disturbances dial-up communication can be effectively utilized.

The cost of the communication of this nature comprise of the fixed cost to be paid as one time Registration fees, Installation fees of the equipment) and the periodical subscription as well as usage charges.

Disadvantages, however, are the same as indicated above for the Leased line communication.

Jan 2008


Communication Selection CriteriaGSM Mobile Communication

With the advent of mobile telephony, usage of GSM communication is becoming quite popular and widely used for data communication. Using GSM modems at the RTU end and the Control Centre end the data exchange can be introduced using urban mobile (GSM) networks.

While considering the GSM network as a feasible solution one has to be sure that mobile connectivity is available at all the RTU locations.

GPRS is also an acceptable solution.

Disadvantages are similar as indicated above for leased line communication. Even more, GSM networks tend to be overloaded during peak hours and might make RTU communication unavailable for quite a while.

Jan 2008


Communication Selection CriteriaDigital Networks via Fiber Optic

It is required to lay extensive FO cables connecting primary stations, sub-divisions and the control centre. Such systems, though The Best technical option to establish a TCP/IP network, requires considerably high cost. In addition to establishing of an extensive FO network, the associated

terminating equipment and multiplexers are required at all the location from where the data is to be collected or to be dropped in.Though the solution does not look to be cost effective at first sight due to high

initial costs, it may turn out to be cost effective, if the utility makes use of the extra fibers of the FO cable for other communication facility requirements such as voice, Fax, other IT applications. With the establishment of an own FO network, the utility has the responsibility

for operation and maintenance of the network, but at the same time it has full control of system expansion in case of increasing number of (field-) RTUs.Fast wireless Ethernet modems are gradually becoming popular. The

Ethernet modems are available in the rated range of 5 miles to 25 miles. Making use of such Ethernet modems together with FO based communication network as backbone, makes an ideal communication between distribution substations, receiving substations and the control centre.

Jan 2008


Communication Selection CriteriaRadio Communication

The communication system using radio requires considerably high costs associated with procurement of radio systems, installation of towers and masts for antennas etc.

However, once installed and put into operation, the communication system has low, annual costs for operations and maintenance. Thus it helps the utility to establish its own communication network.

It is necessary to obtain the frequency allotment / approval from the wireless agency or the prescribed authority as nominated by the state / govt. In general, yearly subscription fees for utilizing the frequency are required to be paid.

Before implementing the solution, a detailed Sight of Line study is required to be carried out for the feasibility of the solution in a particular town / city. Obstruction make occur due to high rise buildings (also by not yet existing ones !).

Jan 2008


Costs

Hardware

Commissioning / Installation

Base fees

Connection fees

Excavation work

Jan 2008


0%

200%

400%

600%

800%

1000%

1200%

1400%

1600%

1800%

Radio (

no tow

er)

Radio B

TC GSM

New pilo

t cable

Leased

line (lo

cal)

Leased

line (fa

r)

Dial m

ode line

DCS C

DC

DCS C

DI

Transmission method

Telecontrol service (RTU) and remote load profile reading Connection feeBase fee

Assembly/commisioning

Hardware cable

Hardware equipment

9 km MV linewith 4 kiosks

Over 5 years 12 polling per day

Invest for assembly and operation

PLC PLC overover Medium Medium VoltageVoltage

*) This calculation depends on the regional conditions, the example based on the European / African market.

Cost Comparison

Jan 2008


Data Transmission with Distribution Line Carrier(DLC)

Jan 2008


The coupling transformer encloses the earthing strap of the MV cable

Conductor 1 Conductor 2 Conductor 3

Sealing end

Earthing strapCDI(ferrite ring)

Earthing bar

BU

Data Transmission with Distribution Line Carrier (DLC) - Inductive coupling device

Jan 2008


CDC

Cable outlet

Conductor 1 Conductor 2 Conductor 3

Bracket or separate supporting bar for CDC

Earthing bar

Connecting element

Data Transmission with Distribution Line Carrier (DLC) - Capacitive coupling device

Jan 2008


CommunicationMulti carrier principleTransmission in the frequency range of

CENELECUniform hardware for Master & SlaveTransmission rates up to 28.8kbit/s

(depending on the line)Bypass of MV switchgearSimple & complex: MV line, tree or ring

networks

Interfaces Telecontrol per IEC 60870-5-101 or DNP 3.0Meters per IEC 61107Medium-voltage line and telecontrol line

Data Transmission with Distribution Line Carrier (DLC) Basic Unit

Jan 2008


Pole mounted switch 1

BU

Control center

Distribution point

MV Line

V.24 IEC 60870-5-101

MV Line

MV substation automation - field trail DLC runs with microRTU and control center by using

IEC communication standard

Test with out-door CDC coupling units Transmission rate 9.6kBd

Pole mounted repeater

BUMaster-

BU

V.24 IEC 60870-5-101BU

V.24 IEC 60870-5-101

Pole mounted switch 2

Data Transmission with Distribution Line Carrier (DLC) Sample project: MEA Bangkok/Thailand

Jan 2008


Mounting a BU cabinet on an overhead line pole

Pole mounted cabinetincluding DCS3000 BU

Fully-installed cabinet, with DCS 3000 BU and SICAM microRTU

Data Transmission with Distribution Line Carrier (DLC) Sample project: MEA Bangkok/Thailand

Jan 2008


BusinessServices

IT Integration

ASP

Administration

Operation

E-Commerce

Maintenance

Field data acquisition,local control & automation

Communication

Network control &supervision (single-or multi-utility)

Added value network management & optimization(applications and systems)

Integrated utility business operation

xxxx x xxx xxx xx

MetersSubstation automation

ProtectionLocal automation

RTUs

PowerExchange

$$TraderPartner, market, etc.

Multi-site

SCADAetc.DB

Networkplanning

Networkinformation

Meter datamanagement

...Advanced applications

(EMS, DMS, EBM, Trading)

Informationgateway

...Asset

ManagementEnergy Sales

& Care

Enterprise Integration Bus

Data Warehouse

MISF&A

Gateway

Power Systems Control and Energy Management Multi-Level Environment

Private & public networks

Jan 2008


Basic SCADA/EMS/DMS System Architecture

DWOperational

Database

Transmission

NA

Distribution

DMS

DSM

Generation

PA

SARO

DW EA

ELCOM

ICCP DTS

DWORACLE

Interfaces

FrontEnd

BASE SCADA

HIS SDM

Base

Interfaces

Jan 2008


Sample SCADA/EMS/DMS Modularity

SCADASCADA

UIUI

FAFA

DSMDSM

PAPA

BaseBase

IS&RIS&R

MultiBCK

MultiBCK

OAOA

TSTS

CFECFE

GEIGEI

ElcomElcom

DataData

DNADNA

GISGIS

LTOPLTOP

GSAGSA

TNATNA

EMMEMM

SDTSDT

IndCIndC

ICCPICCP

MultiBck Multisite/Backup SystemBase Base SystemCFE Communication Front EndData Data EngineeringDNA Distribution Network ApplicationsDSM Demand Side ManagementELCOM Electricity Utilities CommunicationEMM Energy Market ManagementFA Forecasting ApplicationsGEI General External InterfaceGIS Interface to GISGSA Generation Scheduling Applications ICCP Inter Control Center Protocol IndC Industrial Communication IS&R Information Storage & RetrievalLTOP Long-Term Operation PlanningOA Operational ApplicationsPA Power ApplicationsSCADA Supervisory Control & Data AcquisitionSDT Software Development ToolsTNA Transmission Network ApplicationsTS Training System and SimulationUI User Interface & Operator Support

Transmission

Distribution

Generation

SCADA

Jan 2008


Advantages of SCADA-integrated DMS Applications (I)

There are solutions available rather where a separate DMS software is linked to the SCADA system. Integrated DMS applications, however, means software components that have been designed and implemented to form an integrated solution together with the SCADA base system.

This provides benefits to the user: Applications obtain current loading/switching states from SCADA Applications are triggered by SCADA (periodically, on event) Switching procedures determined by applications are automatically,

fast and securely executed via the SCADA system Closed-loop applications possible (e.g. VVC)

Jan 2008


Advantages of SCADA-integrated DMS Applications (II)

There are solutions available rather where a separate DMS software is linked to the SCADA system. Integrated DMS applications, however, means software components that have been designed and implemented to form an integrated solution together with the SCADA base system.

This provides benefits to the user: same user interface - less training effort, staff is productive earlier same system base - no extra cost for dealing with another system base same data model - less effort for data maintenance common database - operator sees consistent values in SCADA and

applications, operators have trust in the applications, operators actually use the applications and realize their benefits common system environment - applications are easy to use, operators

actually use the applications and realize their benefits

Jan 2008


System ConfigurationNon-Redundant All-In-One System

UI : User InterfaceRTS : Real Time Server (SCADA)CFE : Communication Front-EndPSOS : Power System Object Server (Data Model)AAS : Advanced Application ServerWeb TS : Web Terminal Server

Jan 2008


System ConfigurationNon-Redundant All-In-One System w/- external UI Clients


Jan 2008


System ConfigurationNon-Redundant Dual-Server System


Jan 2008


System ConfigurationRedundant Multi-Server System


Jan 2008


Legend:MMI Man-Machine-InterfaceIM/AC Information ManagementISR Information Storage & RetrievalFE Front End DMS Distribution Management SystemRTU Remote Terminal UnitGPS Global Positioning System

SCADA-DMS LAN

IM / ISRServerIM / ISR

Server

Support

Router /Modem

ICCPServerICCP

Server

SCADA-DMSServerSCADA-DMS

Server

Support

2 x Laser printer b/w

Laser printer color

Support

GPS Time system

WebServer

Firewall

m-Term

Operation

Rear projection Walls

84

Operation

m-Term

84

Corporate Network

to PDSFront-end

ServerFront-endServer

RTURTURTURTUSerialinterfacesSerial

interfacesPrimary

Substations

Ultimately:IEC 60 870-5-104

Initially:IEC 60870-5-101

to Bckp

Integration Solution for GIS Interface

SAPGIS AMR

Jan 2008



SCADA-DMS LAN


Server

Support

Router /Modem

ICCPServerICCP

Server


Server

Support


Laser printer color

Support

GPS Time system

WebServer

Firewall

m-Term

Operation


84

Operation

m-Term

84

Corporate Network

to PDSFront-end



interfacesPrimary

Substations



to Bckp

Integration Solution for SAP Interface

SAPGIS AMR

Jan 2008



SCADA-DMS LAN

redundant


Server

Support

Router /Modem

ICCPServerICCP

Server


Server

Support


Laser printer color

Support

GPS Time system

WebServer

Firewall

m-Term

Operation


84

Operation

m-Term

84

Corporate Network

to PDSFront-end



interfacesPrimary

Substations



to Bckp

Integration Solution for AMR Interface

SAPGIS AMR

Meter

Jan 2008


Possible control center structural configurations

MCC

CC 1 CC 2

Independent CCs with different software configuration

CC 1

CC 2 CC 3

Independent CCs with different software configuration and data exchange over ICCP with CC1

CC 1

CC 2 CC 3

Dependent CCs in Multi-Site configuration, with centralized database maintenance and data

exchange

??

Jan 2008


Multisite Operation of Control Centers

Multiple Control Centers in a hierarchical and/or equal-rank configuration can cooperatively manage a power system.

Multisite keeps statuses and values in the process images of the Control Centers up-to-date with statuses and values from other Control Centers and distributes supervisory control commands, manual updates, tagging and alarm acknowledgments.

Jan 2008


Multisite Operation of Control CentersFeatures

Exchange of information between Control Centers Uniform data model and central data management, i.e.

reduced maintenance effort Controlling the network from different Control Centers Increased availability Compensation of communication failures (i.e. automatic

transmission of missing data after return of the connection)

Possibility of delegating operator tasks permanently or during periods where Control Centers are un-staffed or understaffed

Provision of backup or emergency systems Simple and fast design of emergency and system

management concepts as well as straightforward implementation (configurability)

Jan 2008


The Multisite concept allows connecting two or more control centers to a Multisite network. Hierarchical or equal-rank configurations and also combinations of them are possible. Each control center is autonomous and independent in the Multisite network.

The control centers can have different hardware combinations anddifferent data. The hardware configuration of one system is not visible to the software system of other control centers, i.e. each control center is regarded as a unit by all other control centers.

All control centers are connected to each other via LAN/WAN links. The control centers communicate with each other via TCP/IP.

Multisite Operation of Control CentersBasic Concept

Jan 2008


Control Center RedundancyMultisite features enable control center redundancy, if the information areas of the control centers are defined with an appropriate large overlapping. Two control centers can share theoperation control tasks for the same area.

Multisite features enable the configuration of an emergencysystem. For this aim, identical information areas are assigned to both control centers. The hardware configuration and functions need not be identical.

Delegation of Operation Control TaskThe operation control task can be moved between the control centers at request of the operator. This allows operating a control center unmanned during periods when management requirements are low e.g. during night time.

Multisite Operation of Control CentersBasic Concept

Jan 2008


Multisite Operation of Control CentersHierarchical Configuration

MainControl Center

MainControl Center

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

RegionalControl Center






Jan 2008


Multisite Operation of Control CentersMain/Backup Configuration

MainControl Center

MainControl Center

BackupControl Center

BackupControl Center

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Information Network

(RTUs, ICCP, ...)

Jan 2008


Sample Main/Backup Configuration

Independent (dual port) communication between RTU and Main/Bckp The Multisite backup concept allows data entry once for both locations Main and Backup are redundant and self-contained Fully automatic update of databases at both locations

Main PC SB BckpPC SB

Port 1 Port 2

RTU

Backup CC LinkFO Link > 2 MBps

Initially: IEC 101Ultimately: IEC 104 via FO

Primary Substations

Jan 2008


Normal operation: Port 1 sends to/receives from Main Port 2 sends to Backup Backup is continuously updated from Main (operator entered data) Backup is ready for take-over at any instant of time without any human interaction


Port 1 Port 2

RTU



Primary Substations


Jan 2008


Disturbed operation: Server fault at ECS standby server at ECS takes over, no other changes, completely

transparent to operator

Fault of communication link to ECS data to /from the affected RTU goes via the Backup CC Link and BCS, no other changes, completely transparent to operator

All servers down at ECS (i.e. incl. spares !) operator at ECS can immediately connect his/her workstation to BCS or operation is performed from BCS


Port 1 Port 2

RTU



Primary Substations

PC PC


Jan 2008


System SecurityIT Trends for SCADA/EMS/DMS

Jan 2008


System SecurityThread Analysis

Jan 2008


System SecurityThread Analysis Potential Attackers

Jan 2008


System SecurityThread Analysis Sample Attacks & Countermeasures

Jan 2008


System Security Multi Level Security Concept

Interconnection(e.g. to other utilityComputer networks,Internet, etc.)

User access to systemfunctionality (none,

view, modify)

Logging(audit records)

User access rights for

controlling the accessto the IMM data model

UserAuthorization

by login

Jan 2008


System Security Typical Secure Network Setup

(*) Support TLS/SSL/PKI Security for ICCP Communications

(*)

Jan 2008


System SecuritySample System Integrity and Confidentiality Methods

Adding, deleting and modifying user profiles with an O/S User Administration application of the SCADA/DMS database management system

Assigning of user roles to users Runtime verification of user authorities Assigning of Areas of Responsibility to users Restricted access by outside parties and security protection against unauthorized

attempts to procure internal passwords

Mechanisms for data authentication to ensure data integrity (complete and unmodified data) and data privacy

Networking and internet security settings, turning off of unnecessary network services All user logon/ logoff activities are logged in the System Alarm Summary list Automatic user logoff with configurable timer (configurable) Password security, including encryption of transmitted and stored passwords Administrator security measures that include enabling account lockout methods,

renaming the account, establishing separate accounts for multiple administrators, setting up an administrator password control process and configuring of administrator access with critical but limited privileges.

Jan 2008


Distribution Automation projects are multi-part/multi-technology

Bulk Data Management SystemsGeographical Information Systems (GIS), Automatic Meter Reading (AMR) systems, etc.

SCADA/DMS Control CenterSevers, consoles, large screen projections, etc.

Communication EquipmentPower Line Carrier, Radio, GSM, etc.

Substation EquipmentMeters, Remote Terminal Units, Motorized Switchgear, etc.

NS

Distribution-Substation

MV MV MV

HV

Cable Overhead-Line

R

R S

R

R

R

Tn.o.

Jan 2008


Distribution Automation projects callfor particular vendor qualifications

9DA systems must be designed as a whole, parts must fit together (interfaces, capacity, redundancy, ...)9DA grows over time9Must stay open to technology advances during

implementation time

9DA constitutes a system/solution business(as opposed to a product business)

9Need long-term vendor stability9Need profound vendor experience in large, complex, multi-

technology projects9Need profound vendor understanding of business processes

in the electricity distribution bus

Scada Siemens

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